System and method for production of reservoir fluids

ABSTRACT

A system and method for lifting reservoir fluids from reservoir to surface through a wellbore having a first tubing string extending through a packer in a wellbore casing. The system includes a bi-flow connector in the first tubing string, a second tubing string in the first tubing string below the bi-flow connector, and a third tubing string in the first tubing string above and connected with the bi-flow connector. A fluid displacement device in the third tubing string is configured to move reservoir fluids to the surface. The first tubing string allows pressured gas to move from the surface through the bi-flow connector to commingle with and lift reservoir fluids through annuli defined by the first and second tubing strings and defined by the casing and the first tubing string. The bi-flow connector is configured to allow simultaneous and non-contacting flow of the downward pressured gas and lifted reservoir fluid.

CROSS-REFERENCE TO RELATED APPLICATIONS

This application is a divisional of co-pending U.S. application Ser. No.14/643,843 filed Mar. 10, 2015, which is a continuation of U.S.application Ser. No. 13/190,078 filed Jul. 25, 2011, now U.S. Pat. No.8,985,221, issued Mar. 24, 2015, which is a continuation-in-part of U.S.application Ser. No. 12/001,152 filed Dec. 10, 2007, now U.S. Pat. No.8,006,756, issued Aug. 30, 2011, which applications are herebyincorporated by reference for all purposes in their entirety.

STATEMENT REGARDING FEDERALLY SPONSORED RESEARCH OR DEVELOPMENT

N/A

REFERENCE TO MICROFICHE APPENDIX

N/A

BACKGROUND OF THE INVENTION

1. Field of the Invention

This invention relates to production systems and methods deployed insubterranean oil and gas wells.

2. Description of the Related Art

Many oil and gas wells will experience liquid loading at some point intheir productive lives due to the reservoir's inability to providesufficient energy to carry wellbore liquids to the surface. The liquidsthat accumulate in the wellbore may cause the well to cease flowing orflow at a reduced rate. To increase or re-establish the production,operators place the well on artificial lift, which is defined as amethod of removing wellbore liquids to the surface by applying a form ofenergy into the wellbore. Currently, the most common artificial liftsystems in the oil and gas' industry are down-hole pumping systems,plunger lift systems, and compressed gas systems.

The most popular form of down-hole pump is the sucker rod pump. Itcomprises a dual ball and seat assembly, and a pump barrel containing aplunger. A string of sucker rods connects the downhole pump to a pumpjack at the surface. The pump jack at the surface provides thereciprocating motion to the rods which in turn provides the reciprocalmotion to stroke the pump, which is a fluid displacement device. As thepump strokes, fluids above the pump are gravity fed into the pumpchamber and are then pumped up the production tubing and out of thewellbore to the surface facilities. Other downhole pump systems includeprogressive cavity, jet, electric submersible pumps and others.

A plunger lift system utilizes compressed gas to lift a free pistontraveling from the bottom of the tubing in the wellbore to the surface.Most plunger lift systems utilize the energy from a reservoir by closingin the well periodically in order to build up pressure in the wellbore.The well is then opened rapidly which creates a pressure differential,and as the plunger travels to the surface, it lifts reservoir liquidsthat have accumulated above the plunger. Like the pump, the plunger isalso a fluid displacement device.

Compressed gas systems can be either continuous or intermittent. Astheir names imply, continuous systems continuously inject gas into thewellbore and intermittent systems inject gas intermittently. In bothsystems, compressed gas flows into the casing-tubing annulus of the welland travels down the wellbore to a gas lift valve contained in thetubing string. If the gas pressure in the casing-tubing annulus issufficiently high compared to the pressure inside the tubing adjacent tothe valve, the gas lift valve will be in the open position whichsubsequently allows gas in the casing-tubing annulus to enter the tubingand thus lift liquids in the tubing out of the wellbore. Continuous gaslift systems work effectively unless the reservoir has a depletion orpartial depletion drive, which results in a pressure decline in thereservoir as fluids are removed. When the reservoir pressure depletes toa point that the gas lift pressure causes significant back pressure onthe reservoir, continuous gas lift systems become inefficient and theflow rate from the well is reduced until it is uneconomic to operate thesystem. Intermittent gas lift systems apply this back pressureintermittently and therefore can operate economically for longer periodsof time than continuous systems. Intermittent systems are not as commonas continuous systems because of the difficulties and expense ofoperating surface equipment on an intermittent basis.

Horizontal drilling was developed to access irregular fossil energydeposits in order to enhance the recovery of hydrocarbons. Directionaldrilling was developed to access fossil energy deposits some distancefrom the surface location of the wellbore. Generally, both of thesedrilling methods begin with a vertical hole or well. At a certain pointin this vertical well, a turn of the drilling tool is initiated whicheventually brings the drilling tool into a deviated position withrespect to the vertical position.

It is not practical to install most artificial lift systems in thedeviated sections of directional or horizontal wells or deep into theperforated section of vertical wells since down-hole equipment installedin these regions may be inefficient or can undergo high maintenancecosts due to wear and/or solids and gas entrained in the liquidsinterfering with the operation of the pump. Therefore, most operatorsonly install down-hole artificial lift equipment in the vertical portionof the wellbore above the reservoir. In many vertical wells withrelatively long perforated intervals, many operators choose to notinstall artificial lift equipment in the well due to the factors above.Downhole pump systems, plunger lift systems, and compressed gas liftsystems are not designed to recover any liquids that exist below thedownhole equipment. Therefore, in many vertical, directional, andhorizontal wells, a column of liquid ranging from hundreds to manythousands of feet may exist below the down-hole artificial liftequipment. Because of the limitations with current artificial liftsystems, considerable hydrocarbon reserves cannot be recovered usingconventional methods in depletion or partial depletion drive directionalor horizontally drilled wells, and vertical wells with relatively longperforated intervals. Thus, a major problem with the current technologyis that reservoir liquids located below conventional down-holeartificial lift equipment cannot be lifted.

There is a need to provide an artificial lift system that will enablethe recovery of liquids in the deviated sections of directional orhorizontal wellbores, and in vertical wells with relatively longperforated intervals.

There is a need to provide an artificial lift system that will enablethe recovery of liquids in vertical wells with relatively longperforated intervals and in the deviated sections of directional andhorizontal wellbores with smaller casing diameters.

There is a need to lower the artificial lift point in vertical wellswith relatively long perforated intervals and in wells with deviated orhorizontal sections.

There is a need to provide a high velocity volume of injection gas tomore efficiently sweep the reservoir liquids from the wellbore.

There is a need to provide a more efficient, less costly wellbore liquidremoval process.

There is a need for a less costly artificial lift method for verticalwells with relatively long perforated intervals and for wells withdeviated or horizontal sections.

There is a need for a less costly and more efficient artificial liftmethod for wells that still have sufficient reservoir energy andreservoir gas to lift liquids from below to above the downholeartificial lift equipment.

Finally, there is a need to provide a more efficient gas and solidseparation method to lower the lift point in wells with deviated andhorizontal sections and for vertical wells with relatively longperforated intervals.

BRIEF SUMMARY OF THE INVENTION

A gas assisted downhole system is disclosed, which is an artificial liftsystem designed to recover by-passed hydrocarbons in directional,vertical and horizontal wellbores by incorporating a dual tubingarrangement. In one embodiment, a first tubing string contains a gaslift system, and a second tubing string contains a downhole pumpingsystem. In the first tubing string, the gas lift system, which ispreferably intermittent, is utilized to lift reservoir fluids from belowthe downhole pump to above a packer assembly where the fluids becometrapped. As more reservoir fluids are added above the packer, the fluidlevel rises in the casing annulus above the downhole pump installed inthe adjacent second tubing string, and the trapped reservoir fluids arepumped to the surface by the downhole pump. In another embodiment, thesecond tubing string contains a downhole plunger system. As reservoirfluids are added above the packer, the fluid level rises in the casingannulus above the downhole plunger installed in the adjacent secondtubing string, and the trapped reservoir fluids are lifted to thesurface by the downhole plunger system.

A dual string anchor may be disposed with the first tubing string tolimit the movement of the second tubing string. The second tubing stringmay be removably attached with the dual string anchor with an on-offtool without disturbing the first tubing string. A one-way valve mayalso be used to allow reservoir fluids to flow into the first tubingstring in one direction only. The one way valve may be placed in thefirst tubing string below the packer to allow trapped pressure below thepacker to be released into the first tubing string. The valve provides apathway to the surface for the gas trapped below the packer. Theresulting reduced back pressure on the reservoir may lead to productionincreases.

In another embodiment, the second tubing string may be within the firsttubing string, and the injected gas may travel down the annulus betweenthe first and second tubing strings. The second string may house a fluiddisplacement device, such as a downhole pumping system or a plunger liftsystem. A bi-flow connector may anchor the second string to the firststring and allow reservoir liquids in the casing tubing annulus to passthrough the anchor to the downhole pump. In one embodiment, the bi-flowconnector may be a cylindrical body having a thickness, a first end, asecond end, a central bore from the first end to said second end, and aside surface. A first channel may be disposed through the thickness fromthe first end to the second end. A second channel may be disposedthrough the thickness from the side surface to the central bore, withthe first channel and second channel not intersecting. Injected gas maybe allowed to pass vertically through the bi-flow connector to liftliquids from below the downhole pump to above the downhole pump. Thebi-flow connector prevents the injected gas from contacting thereservoir liquids flowing through the bi-flow connector. Alsocontemplated are multiple channels in addition to the first channel andmultiple channels in addition to the second channel.

In yet another embodiment, gas from the reservoir lifts reservoirliquids from below the fluid displacement device, such as a downholepump or a plunger, to above the fluid displacement device. A firsttubing string may contain the fluid displacement device above a packerassembly. A blank sub may be positioned between an upper perforated suband a lower perforated sub in the first tubing string below the fluiddisplacement device. A second tubing string within the first tubingstring and located below the lower perforated sub may lifts liquidsusing the gas from the reservoir.

BRIEF DESCRIPTION OF THE DRAWINGS

For a further understanding of the nature and objects of the presentinvention, reference is had to the following figures in which like partsare given like reference numerals and wherein:

FIG. 1 depicts a directional or horizontal wellbore installed with aconventional rod pumping system of the prior art.

FIG. 2 depicts a conventional gas lift system in a directional orhorizontal wellbore of the prior art.

FIG. 3 depicts an embodiment of the invention utilizing a rod pump and agas lift system.

FIG. 4 depicts another embodiment of the invention similar to FIG. 3except with no internal gas lift valve.

FIG. 5 depicts yet another embodiment of the invention having a Y block.

FIG. 6 depicts another embodiment of the invention similar to FIG. 5except with no internal gas lift valve.

FIG. 7 depicts another embodiment similar to FIG. 3, except with a dualstring anchor and an on-off tool.

FIG. 8 depicts another embodiment similar to FIG. 7, except with nointernal gas lift valve.

FIG. 9 depicts another embodiment similar to FIG. 7, except with aone-way valve.

FIG. 10 is the embodiment of FIG. 9, except shown in a completelyvertical wellbore.

FIG. 11 is an embodiment similar to FIG. 11, except that an alternativeembodiment plunger lift system is installed in place of the downholepump system, and with no surface tank and no dual string anchor.

FIG. 12 depicts another embodiment in a vertical wellbore utilizing abi-flow connector.

FIG. 13 is the embodiment of FIG. 12 except in a horizontal wellbore.

FIG. 13A is an isometric view of a bi-flow connector.

FIG. 13B is a section view along line 13A-13A of FIG. 13.

FIG. 13C is a top view of FIG. 13A.

FIG. 13D is a section view similar to FIG. 13B except with the bi-flowconnector threadably attached at a first end with a first tubular and ata second end with a second tubular.

FIG. 14 is the embodiment of FIG. 13 except that an alternativeembodiment plunger lift system is installed in place of the downholepump system.

FIG. 15 depicts another embodiment that utilizes gas that emanates fromthe reservoir to lift liquids from the curved or horizontal section ofthe wellbore.

FIG. 16 is the embodiment of FIG. 15 except it is shown in a verticalwellbore.

FIG. 17 is the embodiment of FIG. 16 except that an alternativeembodiment plunger lift system is installed in place of the downholepump system.

DETAILED DESCRIPTION OF THE INVENTION

FIG. 1 shows one example of a conventional rod pump system of the priorart in a directional or horizontal wellbore. As set out in FIG. 1,tubing 1, which contains pumped liquids 13 is mounted inside a casing 6.A pump 5 is connected at the end of tubing 1 in a seating nipple 48nearest the reservoir 9. Sucker rods 11 are connected from the top ofpump 5 and continue vertically to the surface 12. Casing 6, cylindricalin shape, surrounds and may be coaxial with tubing 1 and extends belowtubing 1 and pump 5 on one end and extends vertically to surface 12 onthe other end. Below casing 6 is curve 8 and lateral 10 which is drilledthrough reservoir 9.

The process is as follows: reservoir fluids 7 are produced fromreservoir 9 and enter lateral 10, rise up curve 8 and casing 6. Becausereservoir fluids 7 are usually multiphase, they separate into annulargas 4 and liquids 17. Annular gas 4 separates from reservoir fluids 7and rises in annulus 2, which is the void space formed between tubing 1and casing 6. The annular gas 4 continues to rise up annulus 2 and thenflows out of the well to the surface 12. Liquids 17 enter pump 5 by theforce of gravity from the weight of liquids 17 above pump 5 and enterpump 5 to become pumped liquids 13 which travel up tubing 1 to thesurface 12. Pump 5 is not considered to be limiting, but may be anydown-hole pump or pumping system, such as a progressive cavity, jetpump, or electric submersible, and the like.

FIG. 2 shows one example of a conventional gas lift system of the priorart in a directional or horizontal wellbore. Referring to FIG. 2, insidethe casing 6, is tubing 1 connected to packer 14 and conventional gaslift valve 22. Below casing 6 is curve 8 and lateral 10 which is drilledthrough reservoir 9. The process is as follows: reservoir fluids 7 fromreservoir 9 enter lateral 10 and rise up curve 8 and casing 6 and entertubing 1. The packer 14 provides pressure isolation which allows annulus2, which is formed by the void space between casing 6 and tubing 1, toincrease in pressure from the injection of injection gas 16. Once thepressure increases sufficiently in annulus 2, conventional gas liftvalve 22 opens and allows injection gas 16 to pass from annulus 2 intotubing 1, which then commingles with reservoir fluids 7 to becomecommingled fluids 18. This lightens the fluid column and commingledfluids 18 rise up tubing 1 and then flow out of the well to surface 12.

FIG. 3 shows an embodiment utilizing a downhole pump and a gas liftsystem in a horizontal or deviated wellbore. Referring to FIG. 3, insidecasing 6, is tubing 1 which begins at surface 12 and contains internalgas lift valve 15, bushing 25, and inner tubing 21. Inner tubing 21 maybe within tubing 1, such as concentric. Bushing 25 may be a section ofpipe whose purpose is to threadingly connect pipe joints using both itsouter diameter and its inner diameter. Bushing 25 may have pipe threadsat one or both ends of its outer diameter, and pipe threads at one orboth ends of its inner diameter. Other types of bushings and connectionmeans are also contemplated. Tubing 1 is sealingly engaged to packer 14.Tubing 1 and inner tubing 21 extend below packer 14 through curve 8 andinto lateral 10, which is drilled through reservoir 9. Inside casing 6and adjacent to tubing 1 is tubing 3, which contains sucker rods 11connected to pump 5. Pump 5 is connected to the end of tubing 3 byseating nipple 48. Tubing 3 is not sealingly engaged to packer 14.

The process may be as follows: reservoir fluids 7 enter lateral 10 andenter tubing 1. The reservoir fluids 7 are commingled with injection gas16 to become commingled fluids 18 which rise up chamber annulus 19,which is the void space formed between inner tubing 21 and tubing 1. Thecommingled fluids 18 then exit through the holes in perforated sub 24.Commingled gas 41 separates from commingled fluids 18 and rises inannulus 2, which is formed by the void space between casing 6 and tubing1 and tubing 3. Commingled gas 41 then enters flow line 30 at thesurface 12 and enters compressor 38 to become compressed gas 33, andtravels through flow line 31 to surface tank 34. The compressor 38 isnot considered to be limiting, in that it is not crucial to the designif another source of pressured gas is available, such as pressured gasfrom a pipeline.

Compressed gas 33 then travels through flow line 32 which is connectedto actuated valve 35. This actuated valve 35 opens and closes dependingon either time or pressure realized in surface tank 34. When actuated,valve 35 opens, compressed gas 33 flows through actuated valve 35 andtravels through flow line 32 and into tubing 1 to become injection gas16. The injection gas 16 travels down tubing 1 to internal gas liftvalve 15, which is normally closed thereby preventing the flow ofinjection gas 16 down tubing 1. A sufficiently high pressure in tubing 1above internal gas lift valve 15 opens internal gas lift valve 15 andallows the passage of injection gas 16 through internal gas lift valve15. The injection gas 16 then enters the inner tubing 21, and eventuallycommingles with reservoir fluids 7 to become commingled fluids 18, andthe process begins again. Liquids 17 and commingled gas 41 separate fromthe commingled fluids 18 and liquids 17 fall in annulus 2 and aretrapped above packer 14. Commingled gas 41 rises up annulus 2 aspreviously described. As more liquids 17 are added to annulus 2, liquids17 rise above and are gravity fed into pump 5 to become pumped liquids13 which travel up tubing 3 to surface 12.

FIG. 4 shows an alternate embodiment similar to the design in FIG. 3except that it does not utilize the internal gas lift valve 15.

FIG. 5 shows yet another alternate embodiment utilizing a downhole pumpand a gas lift system in a horizontal or deviated wellbore with adifferent downhole configuration from FIG. 3. Referring to FIG. 5,inside the casing 6 is tubing 1 which contains an internal gas liftvalve 15 and is sealingly engaged to packer 14. Packer 14 is preferablya dual packer assembly and is connected to Y block 50 which in turn isconnected to chamber outer tubing 55. Chamber outer tubing 55 continuesbelow casing 6 through curve 8 and into lateral 10 which is drilledthrough reservoir 9. Inner tubing 21 is secured by chamber bushing 22 toone of the tubular members of Y Block 50 leading to lower tubing section37. Inner tubing 21 may be concentric with chamber outer tubing 55. Theinner tubing 21 extends inside of Y block 50 and chamber outer tubing 55through the curve 8 and into the lateral 10. The second tubing stringarrangement comprises a lower section 37 and an upper section 36. Thelower section 37 comprises a perforated sub 24 connected above a one wayvalve 28 and is then sealingly engaged in the packer 14.

Perforated sub 24 is closed at its upper end and is connected to theupper tubing section 36. Upper tubing section 36 comprises a gas shroud58, a perforated inner tubular member 57, a cross over sub 59 and tubing3 which contains pump 5 and sucker rods 11. The gas shroud 58 is tubularin shape and is closed at its lower end and open at its upper end. Itsurrounds perforated inner tubular member 57, which extends above gasshroud 58 to crossover sub 59 and connects to the tubing 3, whichcontinues to the surface 12. Above the crossover sub 59, and containedinside of tubing 3 at its lower end, is pump 5 which is connected tosucker rods 11, which continue to the surface 12. Annular gas 4 travelsup annulus 2 into flowline 30 which is connected to compressor 38 whichcompresses annular gas 4 to become compressed gas 33. The compressor 38is not considered to be limiting, in that it is not crucial to thedesign if another source of pressured gas is available, such aspressured gas from a pipeline.

Compressed gas 33 flows through flowline 31 to surface tank 34 which isconnected to a second flowline 32 that is connected to actuated valve35. This actuated valve 35 opens and closes depending on either time orpressure realized in surface tank 34. When actuated valve 35 opens,compressed gas 33 flows through actuated valve 35 and travels throughflowline 32 and into tubing 1 to become injection gas 16. The injectiongas 16 travels down tubing 1 to internal gas lift valve 15, which isnormally closed thereby preventing the flow of injection gas 16 downtubing 1. A sufficiently high pressure in tubing 1 above internal gaslift valve 15 opens internal gas lift valve 15 and allows the passage ofinjection gas 16 through internal gas lift valve 15, through Y Block 50and into chamber annulus 19, which is the void space between innerconcentric tubing 21 and chamber outer tubing 55. Injection gas 16 isforced to flow down chamber annulus 19 since its upper end is isolatedby chamber bushing 25. Injection gas 16 displaces the reservoir fluids 7to become commingled fluids 18 which travel up the inner concentrictubing 21.

Commingled fluids 18 travel out of inner concentric tubing 21 into oneof the tubular members of Y Block 50, through packer 14 and standingvalve 28, and then through the perforated sub 24 into annulus 2, wherethe gas separates and rises to become annular gas 4 to continue thecycle. The liquids 17 separate from the commingled fluids 18 and fall bythe force of gravity and are trapped in annulus 2 above packer 14 andare prevented from flowing back into perforated sub 24 because ofstanding valve 28. As liquids 17 accumulate in annulus 2, they riseabove pump 5 and are forced by gravity to enter inside of gas shroud 58and into perforated tubular member 57 where they travel up cross-oversub 59 to enter pump 5 where they become pumped liquids 13 and arepumped up tubing 3 to the surface 12.

FIG. 6 shows an alternate embodiment of the invention similar to thedesign in FIG. 5 except that it does not utilize the internal gas liftvalve 15.

FIG. 7 shows an alternate embodiment similar to FIG. 3, except thatthere is a downhole anchor assembly or dual string anchor 20 disposedwith first tubing string 1 and installed and attached with second tubingstring with on-off tool 26. Referring to FIG. 7, first tubing string 1is inside casing 6. First tubing string 1 begins at the surface 12 andcontains internal gas lift valve 15, bushing 25, perforated sub 24, andinner tubing 21. Perforated sub 24 is available from WeatherfordInternational of Houston, Tex., among others. Tubing 1 is engaged todual string anchor 20 and continues through it and is engaged to packer14 and extends through it. Inner tubing 21 connects to bushing 25 andcontinues through perforated sub 24, dual string anchor 20, packer 14and terminates prior to the end of tubing 1. Dual string anchor 20 isavailable from Kline Oil Tools of Tulsa, Okla., among others. Othertypes of dual string anchors 20 are also contemplated. Inner tubing 21may be within tubing 1. Tubing 1 extends through and below dual stringanchor 20 and through and below packer 14 through curve 8 and intolateral 10, which is drilled through reservoir 9. Second tubing string 3is inside casing 6 and adjacent to first tubing string 1. Second tubingstring 3 contains perforated sub 23, sucker rods 11, pump 5, seatingnipple 48, and on-off tool 26. Second tubing string 3 may be selectivelyengaged to dual string anchor 20 with on-off tool 26. On-off tool 26 isavailable from D&L Oil Tools of Tulsa, Okla. and from WeatherfordInternational of Houston, Tex., among others. Other types of on-off tool26 and attachment means are also contemplated. On-off tool 26 may bedisposed with perforated sub 23, which may be attached with secondtubing string 3.

The process for FIG. 7 is similar to that for FIG. 3. The dual stringanchor 20 functions to immobilize the second tubing string 3 bysupporting it with first tubing string 1. Immobilization is important,since in deeper pump applications, the mechanical pump 5 may inducemovement to second tubing string 3 which may in turn cause wear on thetubulars. Movement may also cause the mechanical pump operation to ceaseor become inefficient. On-off tool 26 allows the second tubing string 3to be selectively connected or disconnected from the dual string anchor20 without disturbing the first tubing string 1. The dual string anchor20 minimizes inefficiencies in the pump and costly workovers to repairwear on the tubing strings. This movement is caused by the movementinduced upon the second tubing string by the downhole pumping system.

FIG. 8 shows another alternate embodiment similar to the design in FIG.7 except that it does not utilize internal gas lift valve 15.

FIG. 9 shows another alternate embodiment similar to the design of FIG.7, except that FIG. 9 includes one-way valve 28 disposed on first tubingstring 1 below packer 14. Referring to FIG. 9, when pressure conditionsare favorable, one-way valve 28 opens to allow reservoir gas 27 to passinto chamber annulus 19. One-way valve 28 may be a reverse flow checkvalve available from Weatherford International of Houston, Tex., amongothers. Other types of one-way valves 28 are also contemplated. Althoughonly one one-valve 28 is shown, it is contemplated that there may bemore than one one-way valve 28 for all embodiments. One-way valve 28 maybe threadingly disposed with a carrier such as a conventional tubingretrievable mandrel or a gas lift mandrel. Other connection types,carriers, and mandrels are also contemplated.

One-way valve 28 functions to allow fluids to flow from outside toinside the device in one direction only. In FIGS. 9-14, one-way valve 28may be placed in the first tubing string 1 below the packer 14 to venttrapped pressure below the packer 14 into the first tubing string 1. Ina vertical well application, this venting may assist the optimumfunctioning of the artificial lift system. One-way valve 28 has at leasttwo functions: (1) it provides a pathway to the surface for reservoirgas 27 trapped below packer 14, and (2) it leads to production increasesby reducing back pressure on the reservoir. As can now be understood,one-way valve 28 may be positioned at a location on first tubing string1, such as below packer 14, that is different than the location whereinjected gas 16 initially commingles with the reservoir fluids whereinner tubing 21 ends. Injected gas 16 may initially commingle withreservoir fluids 7 at a first location, and one-way valve 28 may bedisposed on first tubing string 1 at a second location. One-way valve 28may be disposed above reservoir 9, although other locations arecontemplated. One-way valve 28 allows the venting of trapped fluids, andallows flow in only one direction.

FIG. 10 shows the embodiment of FIG. 9 in a completely verticalwellbore.

As can now be understood, dual string anchor or dual tubing anchor 20with on-off tool 26 and one way-valve 28 may be used independently,together, or not at all. For all embodiments in deviated, horizontal, orvertical wellbore applications, there may be (1) gas lift valve 15, dualstring anchor 20, and one-way valve 28 below packer 14, (2) no gas liftvalve 15, no dual string anchor 20, and no one-way valve 28 below packer14, or (3) any combination or permutation of the above. Surface tank 34and actuated valve 35 are also optional in all the embodiments.

FIG. 11 is an embodiment similar to FIG. 10 in which pump 5 and suckerrods 11 have been replaced with an alternative embodiment plunger liftsystem, and there is no surface tank 34 and no one-way valve 28.Referring to FIG. 11, the process is as follows. Initially, actuatedvalve 37 is open at surface 12, which allows flow from tubing 3 tosurface 12. Actuated valve 35 is open and actuated valve 36 is closed.Supply gas 46, which may emanate from the well or a pipeline, iscompressed by compressor 38 and compressed gas 33 flows through flowline 31, through actuated valve 35 and flow line 32, and into tubing 1to become injection gas 16, which then flows down tubing 1, through gaslift valve 15, and through inner tubing 21. At the end of inner tubing21, injection gas 16 combines with reservoir fluids 7 to becomecommingled fluids 18, which rise up chamber annulus 19 and flow throughperforated sub 24 into annulus 2. Liquids 17 fall to the bottom ofannulus 2.

As more liquids are added in annulus 2, they eventually rise aboveplunger 5 and into tubing 3 and rise above perforated sub 24, which maycause the injection pressure to rise which signals actuated valve 35 toclose, actuated valve 39 to open, and actuated valve 37 to close.Compressed gas 33 then flows through actuated valve 36 and through flowline 30, and into annulus 2 to become injection gas 16. When asufficient volume of injection gas 16 has been added to annulus 2, thepressure in annulus 2 rises sufficiently to signal actuated valve 37 toopen, actuated valve 36 to close, and actuated valve 35 to open. Thepressure differential lifts plunger 45 off of seating nipple 48 andrises up tubing 3 and pushes liquids 17 to surface 12. Some injectiongas 16 also flows to surface 12 via tubing 3. Once the pressure ontubing 3 drops sufficiently, plunger 45 falls back down to seatingnipple 48 and the process begins again. Other sequences of the timing ofthe opening and closing of the actuated valves are contemplated. Surfacetank 34 may also be utilized.

FIG. 12 is another embodiment and utilizes an outer and inner tubingarrangement, such as concentric, incorporating a novel bi-flow connector43 in a vertical wellbore. The bi-flow connector 43 is shown in detailin FIGS. 13A-13D and discussed in detail below. FIG. 13 is similar toFIG. 12 except in a horizontal wellbore. Although FIG. 13 is discussedbelow, the discussion applies equally to FIG. 12. In FIG. 13, firsttubing string 1 begins at surface 12 and is installed inside casing 6,contains bi-flow connector 43, bushing 25, one way valve 29, and issealingly engaged to packer 14. Mud anchor 40 may be connected tobi-flow connector 43 to act as a reservoir for particulates that fallout of liquids 17, and to isolate the injection gas 16 from liquids 17.Mud anchor 40 is a tubing with one end closed and one end open, and isavailable from Weatherford International of Houston, Tex., among others.First tubing string 1 continues below packer 14 and contains one wayvalve 28 and continues until it terminates in curve 8 or lateral 10, orfor FIG. 12 in or below reservoir 9. Within first tubing string 1 issecond tubing string 21, which is also sealingly engaged to bushing 25and continues down through packer 14 and may terminate prior to the endof first tubing string 1. Third tubing string 3 is within first tubingstring, and begins at surface 12 and terminates in on-off tool 26.On-off tool 26 allows third tubing string 3 to be selectively engaged tofirst tubing string 1. On-off tool 26 is sealingly engaged to bi-flowconnector 43. Contained inside first tubing string 3 are sucker rods 11,pump 5 and seating nipple 48. Sucker rods 11 are connected to pump 5which is selectively engaged into seating nipple 48. Seating nipple 48is available from Weatherford International of Houston, Tex., amongothers.

As shown in FIGS. 13A-13D, bi-flow connector 43 is a cylindricallyshaped body with a central bore 112 extending from a first end 105 to asecond end 107 and having a thickness 109. Vertical or first channels102 pass through the thickness 109 of the bi-flow connector 43 from thefirst end 105 to the second end 107. Horizontal or second channels 100pass from the side surface 111 through the thickness 109 of the bi-flowconnector 43 to the central bore 112. Although shown vertical andhorizontal, it is also contemplated that first channels may not bevertical and second channels may not be horizontal. Different numbersand orientations of channels are contemplated. The first channels 102and second channels 100 do not intersect. Threads 104, 108 are on theside surface 111 of the bi-flow connector 43 adjacent its first andsecond ends 105, 107. There may also be inner threads 106, 110 on theinner surface of the central bore 112 adjacent the first and secondends. As shown in FIGS. 12-13, the mud anchor 40 is attached with theinner threads 110, and the first tubing string 1 is attached with theouter threads 104, 108. In FIG. 13D, the threaded connection between thebi-flow connector 43 between upper tubular 114 and lower tubular 116 issimilar to the connection in FIG. 13 between the bi-flow connector 43and first tubing string 1.

Returning to FIG. 13, the process may be as follows. Injection gas 16travels down annulus 47 and passes vertically through bi-flow connector43 and continues down through bushing 25, packer 14, second tubingstring 21 and out into first tubing string 1 where it commingles withreservoir fluids 7 to become commingled fluids 18. Reservoir gasemanates from reservoir 9 and may travel through one way valve 28 andbecome part of commingled fluids 18, which rise up annulus 19 and travelthrough one way valve 29 and then separate into liquids 17 andcommingled gas 41. Liquids 17 may enter horizontally through bi-flowconnector 43 and up to pump 5 where they become pumped liquids 13 andare pumped to surface 12. Commingled gas 41 rises up annulus 2 tosurface 12.

As can now be understood, the bi-flow connector 43 allows downwardinjection gas to pass vertically through the tool, while simultaneouslyallowing reservoir liquids to pass horizontally through the tool,without commingling the reservoir liquids with the downwardly flowinginjection gas. The bi-flow connector 43 also allows the inner tubingstring, such as third tubing string 3, to be selectively engaged to theouter tubing string, such as first tubing string 1. The bi-flowconnector 43 may be used in small casing diameter wellbores in which theinstallation of two side by side or adjacent tubing strings isimpractical or impossible. The bi-flow connector 43 is advantageous towells that have a smaller diameter casing. Other non-concentric tubingarrangement embodiments may require larger casing sizes. A plungersystem is also contemplated in place of the downhole pump.

FIG. 14 is the same embodiment as FIG. 13 except that an alternativeembodiment plunger lift system is installed in place of the downholepump system. A pump and a plunger are both fluid displacement devices.

FIG. 15 is another embodiment using only reservoir gas to lift thereservoir liquids from below the downhole pump to above the downholepump. This embodiment is similar to FIG. 13, but no inner tubing, suchas third tubing string 3, is needed to house the downhole pump and noexternal injection gas is needed. It may also incorporate a one wayvalve 28 in the tubing string to prevent wellbore liquids from fallingback down the wellbore. The one way valve 28 allows the liquids to betrapped above the packer until the pump can lift them to the surface.The smaller diameter of the inner tubing efficiently lifts reservoirfluids by forcing the reservoir gas into a smaller cross-sectional areawhereby the gas is not allowed to rise faster than the reservoirliquids. Due to the smaller tubing size, a relatively small amount ofreservoir gas can lift reservoir liquids the relatively short distancefrom the end of the tubing to the one way valve.

Referring to FIG. 15, first tubing string 1 begins at surface 12 andcontains seating nipple 48, upper perforated sub 23, blank sub 42, lowerperforated sub 24, one way valve 39, on-off tool 26, packer 14, bushing25 and terminates in curve 8 or lateral 10. Seating nipple 48, blank sub42, perforated subs 23, 24, on-off tool 26, packer 14, one way valve 39,and bushing 25 are all available from Weatherford International ofHouston, Tex., among others. Connected to seating nipple 48 is pump 5which is connected to sucker rods 11 which continue up to surface 12.Connected to bushing 25 is second tubing string 21 which is connected toone way valve 28, and continues down the wellbore and may terminateprior to the end of tubing 1.

The process may be as follows. Reservoir fluids 7 emanate from reservoir9 and enter lateral 10 and then enter first tubing string 1 and secondtubing string 21. Gas in reservoir fluids 7 expand inside second tubingstring 21 and lift reservoir fluids 7 up and out of second tubing string21 into first tubing string 1, through on-off tool 26, through one wayvalve 39 and out of lower perforated sub 24 and into annulus 2.Reservoir fluids 7 separate into liquids 17 and annular gas 4. Liquids17 enter into upper perforated sub 23 and then enter into pump 5 wherethey become pumped liquids 13 and are pumped to surface 12 via tubing 1.Annular gas 4 rises up annulus 2 to surface 12.

FIG. 16 is the embodiment of FIG. 15 except in a vertical wellbore.

FIG. 17 is the embodiment of FIG. 16 except that a plunger has beeninstalled in place of the sucker rods and pump. The plunger may beoperated merely by the periodic opening and closing of the first tubingstring 1 to the surface or it may be operated by the periodic orcontinuous injection of gas down the annulus combined with the periodicopening and closing of the first tubing string 1 to the surface. Bothmethods will force the plunger and liquids above it to the surface. Thisembodiment is much less expensive than installing a downhole pump. Thisdesign is advantageous for wells that have sufficient reservoir energyand gas production to lift liquids from below the downhole pump to abovethe downhole pump, yet still require artificial lift equipment to liftthese liquids to the surface. This embodiment is less costly to installsince no injection gas from the surface is required. Subsequently thereis no gas injection tubing, no surface tank, no actuated valve, nocompressor, and no dual string anchor. It will also accommodatewellbores with smaller casing diameters.

The embodiment of FIGS. 15-16 is advantageous for wells that havesufficient reservoir energy and gas production to lift liquids frombelow the downhole pump to above the downhole pump, yet still requireartificial lift equipment to lift these liquids to the surface. Thisembodiment is less costly to install since no injection gas from thesurface is required. There does not have to be any gas injection tubing,surface tank, actuated valve, compressor, or dual string anchor. It willalso accommodate wellbores with smaller casing diameters. The embodimentof FIG. 17 is even less expensive because there does not have to be anydownhole pump and related equipment.

An advantages of all embodiments is a lower artificial lift point andbetter recovery of hydrocarbons. There is better gas and particulateseparation in all embodiments. In FIGS. 3-11, the entry point for thecommingled fluids is above the intake of the pump or other fluiddisplacement device, which helps break out any gas in the fluids sincegravity will segregate the gas from the liquids. The same is true forparticulates since there is a large reservoir for them to collect inbelow the pump. In FIGS. 12-17, the gas is discouraged from entering theperforated subs because of gravity separation.

Because many varying and different embodiments may be made within thescope of the invention concept taught herein which may involve manymodifications in the embodiments herein detailed in accordance with thedescriptive requirements of the law, it is to be understood that thedetails herein are to be interpreted as illustrative and not in alimiting sense.

I claim:
 1. A method for moving reservoir fluids in a wellbore to thesurface, comprising the steps of: positioning a cylindrical body in thewellbore; wherein said body having a thickness, a first end, a secondend, a central bore from said first end to said second end, a sidesurface, a first channel disposed through said thickness from said firstend to said second end, a second channel disposed through said thicknessfrom said side surface to said central bore; and wherein said firstchannel and said second channel do not intersect; moving a pressured gasdownwardly from the surface through said first channel; and moving thereservoir fluids through said second channel.
 2. The artificial liftsystem of claim 1, wherein there are more than one channel disposedthrough said thickness from said first end to said second end; andwherein there are more than one channel disposed through said thicknessfrom said side surface to said central bore.